SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) [X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 1999 -------------------- OR [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from ______ to_______ SOUTHERN CALIFORNIA GAS COMPANY - ------------------------------------------------------------------- (Exact name of registrant as specified in its charter) CALIFORNIA 1-1402 95-1240705 - ------------------------------------------------------------------- (State of incorporation (Commission (I.R.S. Employer or organization) File Number) Identification No. 555 WEST FIFTH STREET, LOS ANGELES, CALIFORNIA 90013 - ------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (213)244-1200 -------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of each exchange Title of each class on which registered - ------------------- --------------------- Preferred Stock Pacific First Mortgage Bonds: Series Y, due 2021; Series Z, due 2002; Series BB, due 2023; Series DD, due 2023; New York Series EE, due 2025; Series FF, due 2003 SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Exhibit Index on page 56. Glossary on page 58. Aggregate market value of the voting preferred stock held by non- affiliates of the registrant as of February 29, 2000 was $13.8 million. Registrant's common stock outstanding as of February 29, 2000 was wholly owned by Pacific Enterprises. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Information Statement prepared for the May 2000 annual meeting of shareholders are incorporated by reference into Part III. TABLE OF CONTENTS PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 11 Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 11 Item 4. Submission of Matters to a Vote of Security Holders. . 11 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . 11 Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . 12 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . 25 Item 8. Financial Statements and Supplementary Data. . . . . . 26 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . 53 PART III Item 10. Directors and Executive Officers of the Registrant . . 53 Item 11. Executive Compensation . . . . . . . . . . . . . . . . 53 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . 54 Item 13. Certain Relationships and Related Transactions . . . . 54 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . 54 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 56 Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 This report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans" "intends," "may" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements that involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements. These statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional, national and international economic, competitive, political and regulatory conditions and developments; technological developments; capital market conditions; inflation rates; interest rates; exchange rates; energy markets, including the timing and extent of changes in commodity prices; weather conditions; business and regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity delivery; and other uncertainties -- all of which are difficult to predict and many of which are beyond the control of the Company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the Company's business described in this annual report and other reports filed by the Company from time to time with the Securities and Exchange Commission. PART I ITEM 1. BUSINESS DESCRIPTION OF BUSINESS A description of Southern California Gas Company (SoCalGas or the Company) is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. GOVERNMENT REGULATION Local Regulation SoCalGas has gas franchises with the 236 legal jurisdictions in its service territory. These franchises allow SoCalGas to locate facilities for the transmission and distribution of natural gas in the streets and other public places. Some franchises have fixed terms, such as that for the city of Los Angeles, which expires in 2012. Most of the franchises do not have fixed terms and continue indefinitely. The range of expiration dates for the franchises with definite terms is 2003 to 2041. State Regulation The California Public Utilities Commission (CPUC) regulates SoCalGas' rates and conditions of service, sales of securities, rate of return, rates of depreciation, uniform systems of accounts, examination of records, and long-term resource procurement. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies. Federal Regulation The Federal Energy Regulatory Commission (FERC) regulates the interstate sale and transportation of natural gas, the uniform systems of accounts and rates of depreciation. Licenses and Permits SoCalGas obtains a number of permits, authorizations and licenses in connection with the transmission and distribution of natural gas. They require periodic renewal, which results in continuing regulation by the granting agency. Other regulatory matters are described throughout this report. SOURCES OF REVENUE Industry segment information is contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the notes to Consolidated Financial Statements herein. NATURAL GAS OPERATIONS Utility Services SoCalGas distributes natural gas throughout a 23,000-square-mile service territory with a population of approximately 18.1 million people. Its service territory includes most of southern California and part of central California. The Company offers two basic utility services, sale of natural gas and transportation of natural gas, through its two business units. One business unit focuses on core distribution customers (primarily residential customers) and the other on large volume gas transportation customers. Natural gas service is also provided on a wholesale basis to the distribution systems of the City of Long Beach, affiliated company SDG&E and Southwest Gas Corporation. Supplies of Natural Gas The Company buys natural gas under several short-term and long-term contracts. Short-term purchases are based on monthly-spot-market prices. The Company has firm pipeline capacity contracts with pipeline companies that expire at various dates through 2006. Most of the natural gas purchased and delivered by the Company is produced outside of California. These supplies are delivered to the Company's intrastate transmission system by interstate pipeline companies, primarily El Paso Natural Gas Company and Transwestern Natural Gas Company. These interstate companies provide transportation services for supplies purchased from other sources by the Company or its transportation customers. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC. Existing pipeline capacity into California exceeds current demand by over 1 billion cubic feet (bcf) per day. The implications of this excess are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. The following table shows the sources of natural gas deliveries from 1995 through 1999. Year Ended December 31 ------------------------------------------------------------------- 1999 1998 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------- Gas Purchases (billions of cubic feet) Spot market 315 270 229 226 206 Long-term 74 101 95 96 99 California producers 2 3 5 12 29 ------- ------- ------- ------- ------- Total Purchases 391 374 329 334 334 Customer-Owned and Exchange Receipts 637 637 614 518 620 Storage Withdrawal (Injection) - net (6) (28) (3) 42 (13) Company Use and Unaccounted For (16) (21) (10) (10) (4) ------- ------- ------- ------- ------- Net Deliveries 1,006 962 930 884 937 ======= ======= ======= ======= ======= Cost of Gas Purchased (millions of dollars) Commodity costs $ 916 $ 774 $ 849 $ 627 $ 478 Fixed charges* 147 174 250 276 264 ------- ------- ------- ------- ------- Total Purchases $1,063 $ 948 $1,099 $ 903 $ 742 ======= ======= ======= ======= ======= Average Cost of Purchases (dollars per thousand cubic feet)** $2.34 $2.07 $ 2.58 $1.88 $1.42 ======= ======= ======= ======= ======= * Fixed charges primarily include pipeline demand charges, take or pay settlement costs and other direct billed amounts allocated over the quantities delivered by the interstate pipelines serving SoCalGas. ** The average commodity cost of natural gas purchased excludes fixed charges. Market sensitive natural gas supplies (supplies purchased on the spot market as well as under longer-term contracts, ranging from one month to ten years, based on spot prices) accounted for 81 percent of total natural gas volumes purchased by the Company during 1999, as compared with 72 percent and 70 percent during 1998 and 1997, respectively. These supplies were generally purchased at prices significantly below those of long-term fixed-price sources of supply. During 1999, the Company delivered 1,006 bcf of natural gas through its system. Approximately 63 percent of these deliveries were customer-owned natural gas for which the Company provided transportation services. The balance of natural gas deliveries was gas purchased by the Company and resold to customers. The Company estimates that sufficient natural gas supplies will be available to meet the requirements of its customers for the next several years. Customers For regulatory purposes, customers are separated into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers, without alternative fuel capability. There are approximately 5.0 million core customers (4.8 million residential and 0.2 million small commercial and industrial). Noncore customers consist primarily of utility electric generation (UEG), wholesale, large commercial, industrial and off-system (outside the Company's normal service territory) customers, and total approximately 1,500. Most core customers purchase natural gas directly from the Company. Core aggregate transportation customers are permitted to aggregate their natural gas requirement and, up to a CPUC-imposed limit of 10 percent of the Company's core market, to purchase natural gas directly from brokers or producers. The Company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. Noncore customers have the option of purchasing natural gas either from the Company or from other sources, such as brokers or producers, for delivery through the Company's transmission and distribution system. The only natural gas supplies that the Company may offer for sale to noncore customers are the same supplies that it purchases for its core customers. Most noncore customers procure their own natural gas supply. In 1999, approximately 87 percent of the CPUC-authorized natural gas margin was allocated to the core customers, with 13 percent allocated to the noncore customers. Although revenue from transportation throughput is less than for natural gas sales, the Company generally earns the same margin whether the Company buys the gas and sells it to the customer or transports natural gas already owned by the customer. The Company also provides natural gas storage services for noncore and off-system customers on a bid and negotiated contract basis. The storage service program provides opportunities for customers to store natural gas on an "as available" basis, usually during the summer to reduce winter purchases when natural gas costs are generally higher. As of December 31, 1999, the Company was storing approximately 22 bcf of customer-owned gas. Demand for Natural Gas Natural gas is a principal energy source for residential, commercial, industrial and UEG customers. Natural gas competes with electricity for residential and commercial cooking, water heating, space heating and clothes drying, and with other fuels for large industrial, commercial and UEG uses. Growth in the natural gas markets is largely dependent upon the health and expansion of the southern California economy. The Company added approximately 74,000 and 46,000 new customer meters in 1999 and 1998, respectively, representing growth rates of approximately 1.5 percent and 0.9 percent, respectively. The Company expects its growth for 2000 will continue at about the 1999 level. During 1999, 99 percent of residential energy customers in the Company's service area used natural gas for water heating, 96 percent for space heating, 76 percent for cooking and 55 percent for clothes drying. Demand for natural gas by noncore customers is very sensitive to the price of competing fuels. Although the number of noncore customers in 1999 was only 1,500, it accounted for 13 percent of the authorized natural gas revenues and 57 percent of total natural gas volumes. External factors such as weather, electric deregulation, the use of hydro-electric power, competing pipeline bypass and general economic conditions can result in significant shifts in this market. The demand for natural gas by large UEG customers is also greatly affected by the price and availability of electric power generated in other areas and purchased by the Company's UEG customers. Natural gas demand in 1999 for UEG customer use increased primarily due to higher electric energy usage in the summer, as a result of warmer weather. UEG customer demand decreased in 1998 as a result of decreased demand for electricity. Effective March 31, 1998, electric industry restructuring gave California consumers the option of selecting their electric energy provider from a variety of local and out-of-state producers. As a result, natural gas demand for electric generation within southern California competes with electric power generated throughout the western United States. Although the electric industry restructuring has no direct impact on the Company's natural gas operations, future volumes of natural gas transported for UEG customers may be adversely affected to the extent that regulatory changes divert electricity from the Company's service area. Other Additional information concerning customer demand and other aspects of natural gas operations is provided under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 10 and 11 of the notes to Consolidated Financial Statements herein. RATES AND REGULATION SoCalGas is regulated by the CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms. It is the responsibility of the CPUC to determine that utilities operate within the best interests of their customers. The regulatory structure is complex and has a substantial impact on SoCalGas' profitability. The natural gas industry is currently undergoing a transition to increased competition. Natural Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In January 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. Additional information on natural gas industry restructuring is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the notes to Consolidated Financial Statements herein. Balancing Accounts In general, earnings fluctuations from changes in the costs of natural gas and consumption levels for the majority of natural gas are eliminated by balancing accounts authorized by the CPUC. Additional information on balancing accounts is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 2 of the notes to Consolidated Financial Statements herein. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for SoCalGas. Additional information on PBR is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the notes to Consolidated Financial Statements herein. Biennial Cost Allocation Proceeding (BCAP) Rates to recover the changes in the cost of natural gas transportation services are determined in the BCAP. The BCAP adjusts rates to reflect variances in customer demand from estimates previously used in establishing customer natural gas transportation rates. The mechanism substantially eliminates the effect on income of variances in market demand and natural gas transportation costs subject to the limitations of the Gas Cost Incentive Mechanism (GCIM) discussed below. The BCAP will continue under PBR. Additional information on the BCAP is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the notes to Consolidated Financial Statements herein. Gas Cost Incentive Mechanism (GCIM) The GCIM is a process SoCalGas uses to evaluate its natural gas purchases, substantially replacing the previous process of reasonableness reviews. Additional information on the GCIM is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the notes to Consolidated Financial Statements herein. Affiliate Transactions In December 1997, the CPUC adopted rules establishing uniform standards of conduct governing the manner in which California investor-owned utilities (IOUs) conduct business with their affiliates. Information on affiliate transactions is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the notes to Consolidated Financial Statements herein. Cost of Capital Under PBR, annual Cost of Capital proceedings have been replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. Additional information on the utilities' cost of capital is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the notes to Consolidated Financial Statements herein. ENVIRONMENTAL MATTERS Discussions about environmental issues affecting SoCalGas, including hazardous substances, are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. The following additional information should be read in conjunction with those discussions. Hazardous Substances SoCalGas lawfully disposed of wastes at permitted facilities owned and operated by other entities. Operations at these facilities may result in actual or threatened risks to the environment or public health. Under California law, businesses that arrange for legal disposal of wastes at a permitted facility from which wastes are later released, or threaten to be released, can be held financially responsible for corrective actions at the facility. SoCalGas has been named as a potential responsible party (PRP) for two landfill sites and three industrial waste disposal sites, from which releases have occurred as described below. In December 1999, SoCalGas was notified that it is a PRP at the Gibson Oil waste treatment facility in Bakersfield, California. SoCalGas is working with other PRPs in order to remove from the site certain liquid wastes that threaten to be released. It is too early to determine the existence or extent of any prior releases or SoCalGas' potential total liability. In addition, the Company has identified and reported to California environmental authorities 42 former manufactured-gas plant sites for which it (together with other users as to 21 of these sites) may have cleanup obligations. As of December 31, 1999, 13 of these sites have been remediated, of which 10 have received certification from the California Environmental Protection Agency. Preliminary investigations, at a minimum, have been completed on 39 of the gas plant sites. At December 31, 1999, SoCalGas' estimated remaining investigation and remediation liability related to hazardous waste sites, including the manufactured-gas plant sites detailed above, was $64 million, of which 90 percent is authorized to be recovered through the Hazardous Cost Substance Recovery Account. SoCalGas believes that any costs not ultimately recovered through rates, insurance or other means, will not have a material adverse effect on SoCalGas' results of operations or financial position. Estimated liabilities for environmental remediation are recorded when amounts are probable and estimable. Amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism are recorded as a regulatory asset. OTHER MATTERS Year 2000 Sempra Energy established an overall company-wide Year 2000 readiness effort that included SoCalGas. There were only a few, very minor year 2000 interruptions to the Company's automated systems and applications with suppliers and customers. Sempra Energy incurred expenses of $48 million (including $7.6 million in 1999) for its Year 2000 readiness effort and expects to incur no additional costs. Research, Development and Demonstration (RD&D) The SoCalGas RD&D portfolio is focused in five major areas: Operations, Utilization Systems, Power Generation, Public Interest and Transportation. Each of these activities provides benefits to customers and society by providing more cost-effective, efficient natural gas equipment with lower emissions, increased safety and reduced environmental mitigation and other utility operating costs. The CPUC has authorized SoCalGas to recover its operating cost associated with RD&D. An annual average of $9 million has been spent for the last three years. Employees of Registrant As of December 31, 1999 SoCalGas had 6,079 employees, compared to 6,148 at December 31, 1998. Wages Field, technical and most clerical employees of SoCalGas are represented by the Utility Workers' Union of America or the International Chemical Workers' Council. The collective bargaining agreement on wages, hours and working conditions remains in effect through March 31, 2000. Negotiations for a new agreement are ongoing. ITEM 2. PROPERTIES Natural Gas Properties At December 31, 1999, SoCalGas owned 2,854 miles of transmission and storage pipeline, 44,595 miles of distribution pipeline and 44,211 miles of service piping. It also owned 10 transmission compressor stations and 6 underground storage reservoirs (with a combined working capacity of approximately 117.8 Bcf). Other Properties SoCalGas has a 15-percent limited partnership interest in a 52- story office building in downtown Los Angeles. SoCalGas leases approximately half of the building through the year 2011. The lease has six separate five-year renewal options. The Company owns or leases other offices, operating and maintenance centers, shops, service facilities, and equipment necessary in the conduct of business. ITEM 3. LEGAL PROCEEDINGS Neither the Company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of the issued and outstanding common stock of SoCalGas is owned by PE, a wholly owned subsidiary of Sempra Energy. The information required by Item 5 concerning dividends declared is included in the "Statements of Consolidated Changes in Shareholders' Equity" set forth in Item 8 of this Annual Report herein. Dividend Restrictions The CPUC regulates SoCalGas' capital structure, limiting the dividends it may pay. At December 31, 1999, $267 million of SoCalGas' retained earnings was available for future dividends. ITEM 6. SELECTED FINANCIAL DATA (Dollars in millions) At December 31, or for the years then ended ------------------------------------------------ 1999 1998 1997 1996 1995 -------- ------- ------- ------- ------- Income Statement Data: Operating Revenues $2,569 $2,427 $2,641 $2,422 $2,279 Operating Income $ 268 $ 238 $ 318 $ 286 $ 300 Dividends on Preferred Stock $ 1 $ 1 $ 7 $ 8 $ 12 Earnings Applicable to Common Shares $ 200 $ 158 $ 231 $ 193 $ 203 Balance Sheet Data: Total Assets $3,532 $3,834 $4,205 $4,354 $4,462 Long-Term Debt $ 939 $ 967 $ 968 $1,090 $1,220 Short-Term Debt (a) $ 30 $ 75 $ 498 $ 409 $ 329 Shareholders' Equity $1,310 $1,382 $1,467 $1,487 $1,645 (a) Includes long-term debt due within one year. Since SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per share data has been omitted. This data should be read in conjunction with the Consolidated Financial Statements and the notes to Consolidated Financial Statements contained herein. </table ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction This section includes management's discussion and analysis of operating results from 1997 through 1999, and provides information about the capital resources, liquidity and financial performance of Southern California Gas Company (SoCalGas or the Company). This section also focuses on the major factors expected to influence future operating results and discusses investment and financing plans. It should be read in conjunction with the consolidated financial statements included in this Annual Report. SoCalGas is the nation's largest natural gas distribution utility. It owns and operates a natural gas distribution, transmission and storage system supplying natural gas throughout a 23,000-square mile service territory comprising most of southern California and part of central California. The Company is the principal subsidiary of Pacific Enterprises (PE or the Parent), which is wholly-owned by Sempra Energy. The Company provides natural gas service to residential, commercial, industrial, utility electric generation and wholesale customers through 5.0 million meters in a service area with a population of 17.6 million. Business Combinations Sempra Energy was formed to serve as a holding company for PE and Enova Corporation (Enova, the parent corporation of San Diego Gas & Electric Company) in connection with a business combination that became effective on June 26, 1998 (the PE/Enova business combination). In connection with the PE/Enova business combination, the holders of common stock of PE and Enova became the holders of Sempra Energy's common stock. The preferred stock of SoCalGas remained outstanding. The combination was a tax-free transaction. Expenses incurred by SoCalGas in connection with this event were $35 million, aftertax, for the year ended December 31, 1998. There were no business-combination costs in 1999. These costs consist primarily of employee-related costs, and investment banking, legal, regulatory and consulting fees. See Note 1 of the notes to the Consolidated Financial Statements for additional information. Capital Resources and Liquidity The Company's operations continue to be a major source of liquidity. In addition, working capital requirements are met primarily through the issuance of short-term and long-term debt. Cash requirements primarily include capital investments in plant. Additional information on sources and uses of cash during the last three years is summarized in the following condensed statement of consolidated cash flows: - ------------------------------------------------------------ SOURCES AND (USES) OF CASH Year Ended December 31 (Dollars in millions) 1999 1998 1997 - ------------------------------------------------------------ Operating Activities $ 483 $ 782 $ 396 ------------------------- Investing Activities: Capital expenditures (146) (128) (159) Other 17 22 40 ------------------------- Total Investing Activities (129) (106) (119) ------------------------- Financing Activities: Dividends paid (279) (166) (258) Redemption of preferred stock -- (75) -- Long-term debt - net (75) (73) (122) Short-term debt - net -- (351) 89 ------------------------- Total Financing Activities (354) (665) (291) ------------------------- Increase (decrease) in cash and cash equivalents $ -- $ 11 $ (14) - ------------------------------------------------------------ Cash Flows From Operating Activities The decrease in cash flows from operating activities in 1999 was primarily due to the return to ratepayers of the previously overcollected regulatory balancing accounts. This decrease was partially offset by lower expenses incurred in connection with the PE/Enova business combination and lower income tax payments in 1999. The increase in cash flows from operating activities in 1998 was primarily due to higher throughput compared to 1997, combined with natural gas costs that were lower than amounts being collected in rates, which resulted in overcollected regulatory balancing accounts at year-end 1998. This increase was partially offset by expenses incurred in connection with the PE/Enova business combination. Cash Flows From Investing Activities Cash flows from investing activities primarily represent capital investment in plant. Capital expenditures increased in 1999 primarily due to internal software development projects during 1999. Capital expenditures were $31 million lower in 1998 primarily due to the shifting of certain functions to Sempra Energy following the PE/Enova business combination. Capital expenditures are estimated to be $220 million in 2000. They will be financed primarily by internally generated funds. Cash Flows From Financing Activities Net cash used in financing activities decreased in 1999 primarily due to lower short-term debt repayments compared to the same period in 1998 and the repurchase of preferred stock in 1998, partially offset by greater dividends to the parent in 1999. Net cash used in financing activities increased in 1998 due to greater short-term debt repayments and the redemption of preferred stock in 1998, partially offset by lower long-term debt issuances. Long-Term and Short-Term Debt In 1999, cash was used for the repayment of $75 million of unsecured notes. In 1998, cash was used for the repayment of $100 million of first-mortgage bonds, and $47 million of Swiss Franc bonds partially offset by the issuance of $75 million of medium-term Notes. Short-term debt repayments included repayment of $94 million of debt issued to finance the Comprehensive Settlement (see Note 11 of the notes to Consolidated Financial Statements Stock Redemption On February 2, 1998, SoCalGas redeemed all of its 7 3/4% Series Preferred Stock at a cost of $25.09 per share, or $75.3 million including accrued dividends. Dividends Dividends paid to parent amounted to $278 million in 1999, compared to $165 million in 1998 and $251 million in 1997. The payment of future dividends and the amount thereof are within the discretion of the board of directors. Capitalization Total capitalization at December 31, 1999 was $2.3 billion. The debt to capitalization ratio was 43 percent at December 31, 1999 and 1998 and 50 percent in December 31, 1997. The decrease in 1998 compared to 1997 was primarily due to the repayment of short-term debt. Cash and Cash Equivalents Cash and cash equivalents were $11 million at December 31, 1999. The Company anticipates that operating cash required in 2000 for capital expenditures, common stock dividends and debt payments will be provided by cash generated from operating activities. In addition to cash from ongoing operations, the Company has multi-year credit agreements that permit term borrowings of up to $400 million. At December 31, 1999 all bank lines of credit were unused. For further discussion, see Note 3 of the notes to Consolidated Financial Statements. Management believes that the sources of funding described above are sufficient to meet short-term and long-term liquidity needs. Ratemaking Procedures To understand the operations and financial results of the Company it is important to understand the ratemaking procedures that the Company follows. The Company is regulated by the California Public Utility Commission (CPUC). It is the responsibility of the CPUC to determine that utilities operate in the best interests of their customers and have the opportunity to earn a reasonable return on investment. In response to utility-industry restructuring, the Company has received approval from the CPUC for Performance-Based Regulation (PBR). Under PBR, regulators allow income potential to be tied to achieving or exceeding specific performance and productivity measures, rather than relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure. See additional discussion of PBR in Note 11 of the notes to Consolidated Financial Statements. The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas industry restructuring decision for core (residential and small commercial) customers prior to January 2000. During the implementation moratorium, the CPUC held hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. See additional discussion of natural gas-industry restructuring below in "Industry Restructuring" and in Note 11 of the notes to Consolidated Financial Statements. Results of Operations 1999 Compared to 1998 Net income for 1999 increased to $201 million compared to net income of $159 in 1998. The increase is primarily due to $35 million, after-tax, of PE/Enova business combination expenses in 1998. Utility natural gas revenues increased 6 percent in 1999 primarily due to lower overcollections in 1999 and higher utility electric generation (UEG) revenues, partially offset by a decrease in residential and commercial and industrial revenues. The increase in UEG revenues was primarily due to higher electric energy usage in the summer, as a result of warmer weather. The decrease in residential and commercial and industrial revenues is due to lower gas prices. The Company's cost of natural gas distributed increased 13 percent in 1999, largely due to an increase in UEG volumes transported. Operating expenses decreased 8 percent in 1999, primarily due to the lower business combination costs (none in 1999 compared to $60 million pretax in 1998). For the fourth quarter of 1999, net income increased to $59 million from $38 million for the fourth quarter of 1998. The increase is primarily due to lower business-combination and operating expenses in 1999 and the favorable resolution of tax related issues. 1998 Compared to 1997 Net income for 1998 decreased to $159 million, compared to net income of $238 million in 1997. The decrease in net income is primarily due to the costs associated with the PE/Enova business combination and lower base margin established at SoCalGas in its PBR decision which became effective on August 1, 1997 (see Note 11 of the notes to Consolidated Financial Statements). The expense related to the business combination was $35 million, aftertax, for 1998. There were no business combination costs in 1997. Utility natural gas revenues decreased 8 percent in 1998 primarily due to the lower natural gas margin established in the SoCalGas' PBR decision, a decrease in the average cost of natural gas and a decrease in sales to utility electric-generation customers. This was partially offset by increased sales to residential customers due to colder weather in 1998. The Company's cost of natural gas distributed decreased 16 percent in 1998, largely due to a decrease in the average price of natural gas purchased, partially offset by increases in sales volume. Operating expenses increased 12 percent in 1998, primarily due to the higher business-combination costs ($60 million pretax in 1998, compared to none in 1997). For the fourth quarter of 1998, net income decreased to $38 million from $51 million for the fourth quarter of 1997. The decrease is primarily due to an increase in business-combination and operating expenses in 1998. Operating Results The table below summarizes the components of utility natural gas and electric volumes and revenues by customer class for 1999, 1998 and 1997. GAS SALES, TRANSPORTATION & EXCHANGE (Dollars in millions, volumes in billion cubic feet) Gas Sales Transportation & Exchange Total ---------------------------------------------------------------------- Throughput Revenue Throughput Revenue Throughput Revenue ---------------------------------------------------------------------- 1999: Residential 275 $1,821 3 $ 10 278 $1,831 Commercial and Industrial 84 452 306 229 390 681 Utility Electric Generation - - 188 77 188 77 Wholesale - - 150 57 150 57 ----------------------------------------------------------------------- 359 $2,273 647 $373 1,006 2,646 Balancing accounts and other (77) --------- Total $2,569 - --------------------------------------------------------------------------------------------- 1998: Residential 269 $1,976 3 $ 11 272 $1,987 Commercial and Industrial 81 466 315 261 396 727 Utility Electric Generation - - 139 66 139 66 Wholesale - - 155 66 155 66 ----------------------------------------------------------------------- 350 $2,442 612 $404 962 2,846 Balancing accounts and other (419) --------- Total $2,427 - --------------------------------------------------------------------------------------------- 1997: Residential 237 $1,726 3 $ 10 240 $1,736 Commercial and Industrial 80 502 314 255 394 757 Utility Electric Generation - - 158 76 158 76 Wholesale 138 67 138 67 ----------------------------------------------------------------------- 317 $2,228 613 $408 930 2,636 Balancing accounts and other 5 --------- Total $2,641 - --------------------------------------------------------------------------------------------- Other Income, Interest Expense and Income Taxes Other Income Other income, which primarily consists of interest income from short-term investments and regulatory-balancing accounts, decreased to an expense of $7 million in 1999 compared to income of $1 million in 1998. The change is primarily due to an increase in interest expense on regulatory balancing accounts partially offset by an increase in interest income on short-term investments. Other income was $7 million in 1997. The change of $6 million in 1998 was primarily due to higher regulatory interest expense in 1997. Interest Expense Interest expense for 1999 decreased to $60 million in 1999 from $80 million in 1998. The decrease is primarily due to the reversal of interest expense in 1999 as a result of favorable tax rulings. Interest expense was $87 million for 1997. The decrease of $7 million in 1998 is primarily due the repayment of short-term debt in 1998. Income Taxes Income tax expense was $182 million, $128 million and $178 million for the years ended December 31, 1999, 1998 and 1997, respectively. The effective income tax rates were 48 percent, 45 percent and 43 percent for the same periods. The increase is due to the increase in income before taxes. See Note 5 of the notes to the Consolidated Financial Statements for additional information. Factors Influencing Future Performance Performance of the Company in the near future will depend primarily on ratemaking and regulatory process, electric and natural gas industry restructuring, and the changing energy marketplace. These and other factors are summarized below. Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. On January 21, 1998, the CPUC released a staff report initiating a proceeding to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California's natural gas consumers. In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas-industry restructuring decision for core customers prior to January 1, 2000. During the implementation moratorium, the CPUC held hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. The Company has been actively participating in this effort and has argued in support of competition intended to maximize benefits to customers rather than to protect competitors. In October 1999, the State of California enacted a law (AB 1421) which requires that gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue-cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a non-utility provider. The law prohibits the CPUC from unbundling distribution-related gas services (including meter reading and billing) and after-meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for most customers. The objective is to preserve both customer safety and customer choice. As a result of electric industry restructuring, natural gas demand for electric generation within southern California competes with electric power generated throughout the western United States. Effective March 31, 1998, California consumers were given the option of selecting their electric energy provider from a variety of local and out-of-state producers. Although the electric industry restructuring has no direct impact on the Company's natural gas operations, future volumes of natural gas transported for UEG customers may be adversely affected to the extent that regulatory changes divert electricity from the Company's service area. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for the Company. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, as well as cost reductions, rather than by relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure. See additional discussion of PBR in Note 11 of the notes to Consolidated Financial Statements. Accounting Standards SoCalGas accounts for the economic effects of regulation on all of its utility operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Under SFAS No. 71, a regulated entity records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover the asset from customers. Regulatory liabilities represent future reductions in revenues for amounts due to customers. See Notes 2 and 11 of the notes to Consolidated Financial Statements for additional information. Affiliate Transactions On December 16, 1997, the CPUC adopted rules establishing uniform standards of conduct governing the manner in which California IOUs conduct business with their affiliates. The objective of these rules, which became effective January 1, 1998, is to ensure that the utilities' energy affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. The CPUC excluded utility-to-utility transactions between SoCalGas and SDG&E from the affiliate-transaction rules in its March 1998 decision approving the PE/Enova business combination. See Notes 1 and 11 of the notes to Consolidated Financial Statements for additional information. Allowed Rate of Return For 2000, SoCalGas is authorized to earn a rate of return on rate base of 9.49 percent and a rate of return on common equity of 11.6 percent, which are unchanged from 1999. The Company can earn more than the authorized rate by controlling costs below approved levels, by experiencing increased volumes of sales not subject to balancing accounts (both of which are subject to revenue sharing, as described in Note 11 of the notes to Consolidated Financial Statements) or by achieving favorable results in certain areas, such as incentive mechanisms that are not subject to revenue sharing. See additional discussion in Note 11 of the notes to Consolidated Financial Statements. Management Control of Expenses and Investment In the past, management has been able to control operating expenses and investment within the amounts authorized to be collected in rates. It is the intent of management to control operating expenses and investments within the amounts authorized to be collected in rates in the PBR decision. The Company intends to make the efficiency improvements, changes in operations and cost reductions necessary to achieve this objective and earn at least its authorized rates of return. However, in view of the earnings- sharing mechanism and other elements of the PBR, it is more difficult to exceed authorized returns to the degree experienced prior to the inception of PBR. See additional discussion of PBR above and in Note 11 of the notes to Consolidated Financial Statements. Noncore Bypass SoCalGas is fully at risk for reductions in noncore volumes due to bypass. However, significant bypass would require construction of additional facilities by competing pipelines. SoCalGas has not had a material reduction in earnings from bypass and it is continuing to reduce its costs to remain competitive and to retain its transportation customers. Noncore Pricing To respond to bypass, SoCalGas has received authorization from the CPUC for expedited review of long-term natural gas transportation service contracts with some noncore customers at lower-than-tariff rates. In addition, the CPUC approved changes in the methodology that eliminates subsidization of core customer rates by noncore customers. This allocation flexibility, together with negotiating authority, has enabled SoCalGas to better compete with new interstate pipelines for noncore customers. Noncore Throughput SoCalGas' earnings will be adversely impacted if natural gas throughput to its noncore customers varies from estimates adopted by the CPUC in establishing rates. There is a continuing risk that an unfavorable variance in noncore volumes may result from external factors such as weather, electric deregulation, the increased use of hydroelectric power, competing pipeline bypass of SoCalGas' system and a downturn in general economic conditions. In addition, many noncore customers are especially sensitive to the price relationship between natural gas and alternate fuels, as they are capable of readily switching from one fuel to another, subject to air-quality regulations. SoCalGas is at risk for the lost revenue. Through July 31, 1999, any favorable earnings effect of higher revenues resulting from higher throughput to noncore customers was limited as a result of the Comprehensive Settlement. The settlement addressed a number of regulatory issues and was approved by the CPUC in July 1994. This treatment will be replaced by the PBR mechanism as adopted in the 1999 BCAP whereby revenue fluctuations will impact earnings (positively or negatively). See Note 11 of the notes to Consolidated Financial Statements for further discussion. Excess Interstate Pipeline Capacity Existing interstate pipeline capacity into California exceeds current demand by over one billion cubic feet (Bcf) per day. This situation has reduced the market value of the capacity well below the Federal Energy Regulatory Commission's (FERC) tariffs. SoCalGas has exercised its step-down option on both the El Paso and Transwestern systems, thereby reducing its firm interstate capacity obligation from 2.25 Bcf per day to 1.45 Bcf per day. FERC-approved settlements have resulted in a reduction in the costs that SoCalGas possibly may have been required to pay for the capacity released back to El Paso and Transwestern that cannot be remarketed. Of the remaining 1.45 Bcf per day of capacity, SoCalGas' core customers use 1.05 Bcf per day at the full FERC tariff rate. The remaining 0.40 Bcf per day of capacity is marketed at significant discounts. Under existing California regulation, unsubscribed capacity costs associated with the remaining 0.40 Bcf per day are recoverable in customer rates. While including the unsubscribed pipeline cost in rates may impact SoCalGas' ability to compete in competitive markets, SoCalGas does not believe its inclusion will have a significant impact on volumes transported or sold. Environmental Matters The Company's operations are subject to federal, state and local environmental laws and regulations governing such things as hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. Because the potential situations in which the Company is faced with environmental issues are in connection with utility operations, capital costs to comply with environmental requirements are generally recovered through the depreciation components of customer rates. California utilities' customers also generally are responsible for 90 percent of the non-capital costs associated with hazardous substances and the normal operating costs associated with safeguarding air and water quality, disposing properly of solid wastes, and protecting endangered species and other wildlife. Therefore, the likelihood of the Company's financial position or results of operations being adversely affected in a significant amount is remote. The environmental issues currently facing the Company or resolved during the latest three-year period include investigation and remediation of its manufactured-gas sites (13 completed as of December 31, 1999 and 29 to be completed) and cleanup of third- party waste disposal sites used by the Company, which has been identified as a Potentially Responsible Party (investigation and remediations are continuing). Derivative Financial Instruments The Company's policy is to use derivative financial instruments to reduce its exposure to fluctuations in interest rates, foreign currency exchange rates and energy prices. Transactions involving these financial instruments are with reputable firms and major exchanges. The use of these instruments exposes the Company to market and credit risks. At times, credit risk may be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. The Company uses energy derivatives to manage natural gas price risk associated with servicing its load requirements. In addition, the Company makes limited use of natural gas derivatives for trading purposes. These instruments include forward contracts, futures, swaps, options and other contracts, with maturities ranging from 30 days to 12 months. In the case of both price-risk management and trading activities, the use of derivative financial instruments by the Company is subject to certain limitations imposed by Company policy and regulatory requirements. See Note 8 of the notes to Consolidated Financial Statements and the "Market Risk Management Activities" section below for further information regarding the use of energy derivatives by the Company. Market Risk Management Activities Market risk is the risk of erosion of the Company's cash flows, net income and asset values due to adverse changes in interest and foreign-currency rates, and in prices for equity and energy. Sempra Energy has adopted corporate-wide policies governing its market- risk management and trading activities. An Energy Risk Management Oversight Committee, consisting of senior officers, oversees company-wide energy-price risk-management and trading activities to ensure compliance with Sempra Energy's stated energy risk management and trading policies. In addition, the Company has groups that monitor and control energy-price risk management and trading activities independently from the groups responsible for creating or actively managing these risks. Along with other tools, the Company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence level. The Company has adopted the variance/covariance methodology in its calculation of VaR, and uses a 95 percent confidence level. Holding periods are specific to the types of positions being measured, and are determined based on the size of the position or portfolios, market liquidity, purpose and other factors. Historical volatilities and correlations between instruments and positions are used in the calculation. The following is a discussion of the Company's primary market- risk exposures as of December 31, 1999, including a discussion of how these exposures are managed. Interest-Rate Risk The Company is exposed to fluctuations in interest rates primarily as a result of its fixed-rate long-term debt. The Company has historically funded operations through long-term bond issues with fixed interest rates. With the restructuring of the regulatory process, greater flexibility has been permitted within the debt- management process. As a result, recent debt offerings have been selected with short-term maturities to take advantage of yield curves or have used a combination of fixed-rate and floating-rate debt. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures when appropriate, based upon market conditions. A portion of the Company's borrowings are denominated in foreign currencies, which expose the Company to market risk associated with exchange-rate movements. The Company has hedged this foreign-currency cash exposure through a swap transaction entered into with a major international bank. The VaR on the Company's fixed-rate long-term debt is estimated at approximately $99 million as of December 31, 1999, assuming a one-year holding period. Energy-Price Risk Market risk related to physical commodities is based upon potential fluctuations in natural gas and electricity prices and basis. The Company's market risk is impacted by changes in volatility and liquidity in the markets in which these instruments are traded. The Company is exposed, in varying degrees, to price risk in the natural gas market. The Company's policy is to manage this risk within a framework that considers the unique markets, operating and regulatory environment. Market Risk SoCalGas may, at times, be exposed to limited market risk in its natural gas purchase, sale and storage activities as a result of activities under the Gas Cost Incentive Mechanism (GCIM). SoCalGas manages this risk within the parameters of the Company's market- risk management and trading framework. As of December 31, 1999, the total VaR of SoCalGas's natural gas positions was not material. Credit Risk Credit risk relates to the risk of loss that would be incurred as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company avoids concentration of counterparties and maintains credit policies with regard to counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances, and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. The Company monitors credit risk through a credit-approval process and the assignment and monitoring of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. Year 2000 Issues Sempra Energy established an overall company-wide Year 2000 readiness effort that included SoCalGas. There were only a few, very minor year 2000 interruptions to the Company's automated systems and applications with suppliers and customers. Sempra Energy incurred expenses of $48 million (including $7.6 million in 1999) for its Year 2000 readiness effort and expects to incur no additional costs. New Accounting Standards In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the effective date of this statement was deferred for one year. As amended, SFAS 133, which is effective for the Company on January 1, 2001, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposures. The effect of this standard on the Company's Consolidated Financial Statements has not yet been determined. Information Regarding Forward-Looking Statements This Annual Report contains statements that are not historical fact and constitute forward looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may" and "should" or similar expressions or discussions of strategy or of plans are intended to identify forward-looking statements that involve risks and uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements. These statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional, national and international economic, competitive, political and regulatory conditions and developments; technological developments; capital market conditions; inflation rates; interest rates; exchange rates; energy markets, including the timing and extent of changes in commodity prices; weather conditions; business, regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity delivery; and other uncertainties - all of which are difficult to predict and many of which are beyond the control of the Company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the Company's business described in this annual report and other reports filed by the Company from time to time with the Securities and Exchange Commission. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by Item 7A is set forth under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Management Activities." ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Southern California Gas Company: We have audited the accompanying consolidated balance sheets of Southern California Gas Company and subsidiaries as of December 31, 1999 and 1998, and the related statements of consolidated income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southern California Gas Company and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with generally accepted accounting principles. /s/ DELOITTE & TOUCHE LLP San Diego, California February 4, 2000 SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME Dollars in millions For the years ended December 31 1999 1998 1997 ------ ------- ------- Operating Revenues $2,569 $2,427 $2,641 ------ ------ ------ Expenses Cost of natural gas distributed 1,032 913 1,088 Operation and maintenance 738 798 712 Depreciation 260 254 251 Income taxes 179 126 174 Other taxes and franchise payments 92 98 98 ------ ------ ------ Total 2,301 2,189 2,323 ------ ------ ------ Operating Income 268 238 318 ------ ------ ------ Other Income and (Deductions) Interest income 16 4 1 Regulatory interest (14) -- 15 Allowance for equity funds used during construction -- 3 2 Taxes on nonoperating income (3) (2) (4) Other - net (6) (4) (7) ------ ------ ------ Total (7) 1 7 ------ ------ ------ Income Before Interest Charges 261 239 325 ------ ------ ------ Interest Charges Long-term debt 74 75 82 Other interest (12) 6 6 Allowance for borrowed funds used during construction (2) (1) (1) ------ ------ ------ Total 60 80 87 ------ ------ ------ Net income 201 159 238 Preferred Dividend Requirements 1 1 7 ------ ------ ------ Earnings Applicable to Common Shares $ 200 $ 158 $ 231 ====== ====== ====== See notes to Consolidated Financial Statements. SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Dollars in millions December 31, 1999 1998 ---------- ---------- ASSETS Utility plant - at original cost $6,177 $6,063 Accumulated depreciation (3,342) (3,111) ------ ------ Utility plant - net 2,835 2,952 ------ ------ Current assets Cash and cash equivalents 11 11 Accounts receivable - trade (less allowance for doubtful receivables of $16 in 1999 and $17 in 1998) 285 440 Accounts and notes receivable - other 14 13 Due from affiliates 73 -- Deferred income taxes 25 157 Natural gas in storage 67 49 Materials and supplies 12 14 Prepaid expenses 15 14 ------ ------ Total current assets 502 698 ------ ------ Regulatory assets 155 173 Investments and other assets 40 11 ------ ------ Total $3,532 $3,834 ====== ====== See notes to Consolidated Financial Statements. SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Dollars in millions December 31, 1999 1998 ----------- ----------- CAPITALIZATION AND LIABILITIES Capitalization Common stock $ 835 $ 835 Retained earnings 447 525 Accumulated other comprehensive income 6 -- ------ ------ Total common equity 1,288 1,360 Preferred stock 22 22 Long-term debt 939 967 ------ ------ Total capitalization 2,249 2,349 ------ ------ Current liabilities Accounts payable - trade 159 153 Accounts payable - other 227 221 Accounts payable - affiliates -- 111 Regulatory balancing accounts overcollected - net 165 129 Other taxes payable 28 31 Accrued income taxes 4 30 Interest accrued 29 46 Current portion of long-term debt 30 75 Other 84 75 ------ ------ Total current liabilities 726 871 ------ ------ Customer advances for construction 27 31 Deferred income taxes - net 319 323 Deferred investment tax credits 56 58 Deferred credits and other liabilities 155 202 ------ ------ Total deferred credits 557 614 ------ ------ Contingencies and commitments (Note 10) Total $3,532 $3,834 ====== ====== See notes to Consolidated Financial Statements. SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS Dollars in millions For the years ended December 31 1999 1998 1997 ------ ------ ------ Cash Flows From Operating Activities Net income $ 201 $ 159 $ 238 Adjustments to reconcile net income to net cash provided by operating activities Depreciation 260 254 251 Deferred income taxes (13) (50) (15) Deferred investment tax credits (2) (3) (3) Allowance for funds used during construction -- (4) (4) Other (46) 1 (21) Changes in working capital components Accounts receivable 154 46 (86) Regulatory balancing accounts 36 484 36 Gas in storage (18) (24) 3 Other current assets 1 (1) (1) Accounts payable (18) (13) (87) Accrued income taxes (26) (9) 50 Other taxes payable (3) 1 2 Deferred income taxes 132 (146) 21 Due to (from) affiliates (184) 81 (14) Other current liabilities 9 6 26 ------ ------ ------ Net cash provided by operating activities 483 782 396 ------ ------ ------ Cash Flows from Investing Activities Capital expenditures (146) (128) (159) Other - net 17 22 40 ------ ------ ------ Net cash used in investing activities (129) (106) (119) ------ ------ ------ Cash Flows from Financing Activities Dividends paid (279) (166) (258) Redemption of preferred stock -- (75) -- Issuance of long-term debt -- 75 120 Payment of long-term debt (75) (148) (242) Increase (decrease) in short-term debt -- (351) 89 ------ ------ ------ Net cash used in financing activities (354) (665) (291) ------ ------ ------ Net increase (decrease) -- 11 (14) Cash and Cash Equivalents, January 1 11 -- 14 ------ ------ ------ Cash and Cash Equivalents, December 31 $ 11 $ 11 $ -- ====== ====== ====== Supplemental Disclosure of Cash Flow Information: Income tax payments, net of refunds $ 100 $ 302 $ 132 ====== ====== ====== Interest payments, net of amount capitalized $ 77 $ 86 $ 75 ====== ====== ====== See notes to Consolidated Financial Statements. SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY For the years ended December 31, 1999, 1998, 1997 (Dollars in millions) | Accumulated | Other Total Comprehensive| Preferred Common Comprehensive Retained Shareholders' Income | Stock Stock Income Earnings Equity - -------------------------------------------------------------------------------------------------- | Balance at December 31, 1996 | $ 97 $ 835 $ 555 $1,487 Net income/comprehensive income $ 238 | 238 238 Preferred stock dividends declared | (7) (7) Common stock dividends declared | (251) (251) - -------------------------------------------------------------------------------------------------- Balance at December 31, 1997 | 97 835 535 1,467 Net income/comprehensive income 159 | 159 159 Preferred stock dividends declared | (1) (1) Common stock dividends declared | (168) (168) Redemption of preferred stock | (75) (75) - -------------------------------------------------------------------------------------------------- Balance at December 31, 1998 | 22 835 525 1,382 Net income 201 | 201 201 Other comprehensive income | Available-for-sale securities 12 | $ 12 12 Pension (6) | (6) (6) ----- | Comprehensive income $ 207 | Preferred stock dividends declared | (1) (1) Common stock dividends declared | (278) (278) - -------------------------------------------------------------------------------------------------- Balance at December 31, 1999 $ 22 $ 835 $ 6 $ 447 $1,310 ================================================================================================== See notes to Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: BUSINESS COMBINATION On June 26, 1998, Enova Corporation (Enova), the parent company of San Diego Gas & Electric (SDG&E), and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas or the Company), combined into a new company named Sempra Energy (Parent). As a result of the combination, (i) each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy and (iii) the preferred stock and preference stock of the combining companies and their subsidiaries remained outstanding. NOTE 2: SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The Consolidated Financial Statements include the accounts of SoCalGas and its subsidiaries. The Company's policy is to consolidate all subsidiaries that are more than 50 percent owned and controlled. All material intercompany accounts and transactions have been eliminated. Effects of Regulation The accounting policies of SoCalGas conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). SoCalGas has been preparing its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," under which a regulated utility may record a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in rates for amounts due to customers. To the extent that portions of the utility operations were to be no longer subject to SFAS No. 71, or recovery was to be no longer probable as a result of changes in regulation or their competitive position, the related regulatory assets and liabilities would be written off. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," affects utility plant and regulatory assets such that a loss must be recognized whenever a regulator excludes all or part of an asset's cost from rate base. Additional information on the effects of regulation on the Company is provided in Note 11. Revenues and Regulatory Balancing Accounts Revenues from utility customers consist of deliveries to customers and the changes in regulatory balancing accounts. Balancing accounts eliminate from earnings most of the fluctuations in prices and volumes of natural gas by adjusting future rates to recover shortfalls from customers or to return excess collections to customers. Regulatory Assets Regulatory assets include unrecovered premium on early retirement of debt, post-retirement benefit costs, deferred income taxes recoverable in rates and other regulatory-related expenditures that the Company expects to recover in future rates. See Note 11 for additional information. Utility Plant This primarily represents the buildings, equipment and other facilities used by SoCalGas to provide natural gas utility service. The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs minus salvage value, is charged to accumulated depreciation. Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the CPUC. The provisions for depreciation as a percentage of average depreciable utility plant was 4.39, 4.36 and 4.35 in 1999, 1998 and 1997, respectively. Inventories Materials and supplies are generally valued at the lower of average cost or market; natural gas is valued by the last-in first-out method. Allowance for Funds Used During Construction (AFUDC) The allowance represents the cost of funds used to finance the construction of utility plant and is added to the cost of utility plant. AFUDC also increases income, partly as an offset to interest charges shown in the Statements of Consolidated Income, although it is not a current source of cash. Comprehensive Income SFAS No. 130, "Reporting Comprehensive Income" requires reporting of comprehensive income and its components (revenues, expenses, gains and losses) in any complete presentation of general-purpose financial statements. Comprehensive income describes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events including, as applicable, minimum pension liability adjustments and unrealized gains and losses on marketable securities that are classified as available-for-sale. Securities are so classified if the company uses the securities in its cash/asset management program whereby the securities may be sold in connection with interest rate changes and cash requirements. At December 31, 1999, the company had one such investment, which increased in value during 1999. That increase is recognized in the "Statement of Consolidated Changes in Shareholders' Equity." Use of Estimates in the Preparation of the Financial Statements The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Cash and Cash Equivalents Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase, or investments that are readily convertible to cash. Basis of Presentation Certain prior-year amounts have been reclassified to conform to the current year's presentation. New Accounting Standard In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," which is effective for the Company on January 1, 2001. The statement requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposures. The effect of this standard on the Company's Consolidated Financial Statements has not yet been determined. NOTE 3: SHORT-TERM BORROWINGS SoCalGas has a $400 million multi-year credit agreement. This agreement expires in 2001 and bears interest at various rates based on market rates and the Company's credit ratings. SoCalGas' lines of credit are available to support commercial paper. At December 31, 1999 and 1998, SoCalGas' bank line of credit was unused. NOTE 4: LONG-TERM DEBT - ------------------------------------------------------------------- December 31, (Dollars in millions) 1999 1998 - ------------------------------------------------------------------- First-Mortgage Bonds 6.875% August 15, 2002 $ 100 $ 100 5.750% November 15, 2003 100 100 8.750% October 1, 2021 150 150 7.375% March 1, 2023 100 100 7.500% June 15, 2023 125 125 6.875% November 1, 2025 175 175 ---------------------------- 750 750 ---------------------------- Unsecured Long-Term Debt 6.210% Notes, November 7, 1999 -- 75 6.375% Notes, October 29, 2001 120 120 8.750% Notes, July 6, 2000 30 30 5.670% Notes, January 15, 2003 75 75 SFr. 15,695,000 6.375% Foreign Interest Payment Securities, May 14, 2006 8 8 ---------------------------- 233 308 ---------------------------- Total 983 1,058 Less: Current portion of long-term debt 30 75 Unamortized debt discount on long-term debt 14 16 ---------------------------- Total $ 939 $ 967 - ------------------------------------------------------------------- Maturities of long-term debt are $30 million in 2000, $120 million in 2001, $100 million in 2002, $175 million in 2003, $0 in 2004 and $558 million thereafter. SoCalGas has CPUC authorization to issue an additional $600 million in long-term debt. First-Mortgage Bonds First-mortgage bonds are secured by a lien on substantially all utility plant. SoCalGas may issue additional first-mortgage bonds upon compliance with the provisions of its bond indenture, which permit, among other things, the issuance of an additional $750 million of first-mortgage bonds as of December 31, 1999. Callable Bonds At the Company's option, certain bonds may be called at a premium. $150 million of the bonds are callable in 2001, $400 million in 2003 and $8 million in 2006. Other Long-Term Debt During 1998, SoCalGas issued $75 million of unsecured debt in medium-term notes used to finance working capital requirements. There were no new issues during 1999. Currency Rate Swaps In May 1996, SoCalGas issued SFr. 15,695,000 of 6.375% Foreign Interest Payment Securities maturing on May 14, 2006. SoCalGas hedged the currency exposure by entering into a swap transaction with a major international bank. As a result, the bond issue, interest payments and other ongoing costs were swapped for fixed annual payments. The securities are renewable at ten-year intervals at reset interest rates. The next put date for the securities is in the year 2006. NOTE 5: INCOME TAXES The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: - ------------------------------------------------------------------ 1999 1998 1997 - ------------------------------------------------------------------ Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 6.8 9.4 5.5 State income taxes - net of federal income tax benefit 7.3 4.7 6.3 Tax credits (0.6) (0.9) (0.7) Other - net (1.0) (3.6) (3.3) ------------------------------ Effective income tax rate 47.5% 44.6% 42.8% - ------------------------------------------------------------------ The components of income tax expense are as follows: - ------------------------------------------------------------------ (Dollars in millions) 1999 1998 1997 - ------------------------------------------------------------------ Current: Federal $36 $233 $138 State 13 64 38 ------------------------------ Total current taxes 49 297 176 ------------------------------ Deferred: Federal 112 (128) 6 State 24 (38) (1) ------------------------------ Total deferred taxes 136 (166) 5 ------------------------------ Deferred investment tax credits-net (3) (3) (3) ------------------------------ Total income tax expense $182 $128 $178 - ------------------------------------------------------------------ Accumulated deferred income taxes at December 31 result from the following: - ------------------------------------------------------------------ (Dollars in millions) 1999 1998 - ------------------------------------------------------------------ Deferred Tax Liabilities: Differences in financial and tax bases of utility plant $423 $449 Regulatory balancing accounts 16 - Other 18 51 ------------------------------ Total deferred tax liabilities 457 500 ------------------------------ Deferred Tax Assets: Investment tax credits 23 25 Regulatory balancing accounts - 51 Comprehensive settlement (see Note 11) 42 95 Other deferred liabilities 98 153 Other - 10 ------------------------------ Total deferred tax assets 163 334 ------------------------------ Net deferred income tax liability 294 166 - ------------------------------------------------------------------ The net liability is recorded on the consolidated balance sheet as follows: - ------------------------------------------------------------------ (Dollars in millions) 1999 1998 - ------------------------------------------------------------------ Current asset $ (25) $(157) Non-current liability 319 323 - ------------------------------------------------------------------ Total $ 294 $ 166 - ------------------------------------------------------------------- NOTE 6: EMPLOYEE BENEFIT PLANS The information presented below describes the plans of the Company. In connection with the PE/Enova business combination described in Note 1, numerous participants were transferred from the Company's plans to plans of related entities. In connection therewith, the Company recorded a $51 million special termination benefit in 1998. Pension and Other Postretirement Benefits The Company sponsors qualified and nonqualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two years, and a statement of the funded status as of each year end: - --------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ----------------------------------------------- (Dollars in millions) 1999 1998 1999 1998 - --------------------------------------------------------------------------------- Weighted-Average Assumptions as of December 31: Discount rate 7.75% 6.75% 7.75% 6.75% Expected return on plan assets 8.00% 8.50% 8.00% 8.50% Rate of compensation increase 5.00% 5.00% 5.00% 5.00% Cost trend of covered health-care charges - - 7.75%(1) 8.00%(1) Change in Benefit Obligation: Net benefit obligation at January 1 $1,156 $1,378 $ 446 $ 463 Service cost 28 33 11 12 Interest cost 77 95 30 31 Plan participants' contributions - - 1 1 Plan amendments - 16 - - Actuarial gain (120) (10) (62) (5) Transfer of liability (2) (6) (204) - (43) Special termination benefits - 48 - 3 Gross benefits paid (78) (200) (18) (16) ----------------------------------------------- Net benefit obligation at December 31 1,057 1,156 408 446 ----------------------------------------------- Change in Plan Assets: Fair value of plan assets at January 1 1,595 1,834 379 343 Actual return on plan assets 453 286 77 61 Employer contributions 1 1 24 30 Plan participants' contributions - - 1 1 Transfer of assets (2) - (326) - (40) Gross benefits paid (78) (200) (18) (16) ----------------------------------------------- Fair value of plan assets at December 31 1,971 1,595 463 379 ----------------------------------------------- Funded status at December 31 914 439 55 (67) Unrecognized net actuarial gain (969) (518) (156) (53) Unrecognized prior service cost 45 50 - (1) Unrecognized net transition obligation 3 3 110 119 ----------------------------------------------- Net asset (liability) at December 31 $ (7) $ (26) $ 9 $ (2) - --------------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004. (2) To reflect transfer of plan assets and liability to Sempra Energy plan for Company employees transferred to Sempra Energy. The following table provides the components of net periodic benefit cost (income) for the plans: - --------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ----------------------------------------------- (Dollars in millions) 1999 1998 1997 1999 1998 1997 - --------------------------------------------------------------------------------- Service cost $ 28 $ 33 $ 32 $ 11 $ 12 $ 13 Interest cost 77 95 95 30 31 30 Expected return on assets (112) (128) (120) (27) (24) (20) Amortization of: Transition obligation 1 1 1 9 9 9 Prior service cost 4 3 3 - - - Actuarial gain (14) (12) (10) - - - Special termination benefit - 48 13 - 3 2 Settlement credit - (30) - - - - Regulatory adjustment 17 - - 24 9 - ----------------------------------------------- Total net periodic benefit cost $ 1 $ 10 $ 14 $ 47 $ 40 $ 34 - --------------------------------------------------------------------------------- The following table provides the amounts recognized on the SoCalGas balance sheet at December 31. - ------------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ---------------------------------------------- (Dollars in millions) 1999 1998 1999 1998 - ------------------------------------------------------------------------------------- Prepaid benefit cost - - $ 9 - Accrued benefit cost $ (1) $(20) - $(2) Additional minimum liability (2) (6) - - Intangible asset 2 - - - Accumulated other comprehensive income (6) - - - - ------------------------------------------------------------------------------------- Net liability (7) (26) 9 (2) - ------------------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percent change in assumed health care cost trend rates would have the following effects: - ------------------------------------------------------------------------ (Dollars in millions) 1% Increase 1% Decrease - ------------------------------------------------------------------------ Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $8 $ (7) Effect on the health care component of the accumulated postretirement benefit obligation $61 $(55) - ------------------------------------------------------------------------ Except for one nonqualified retirement plan, all pension plans had plan assets in excess of accumulated benefit obligations. For that one plan, the projected benefit obligation and accumulated benefit obligation were $12 million and $9 million, respectively, as of December 31, 1999, and $15 million and $12 million, respectively, as of December 31, 1998. Other postretirement benefits include medical benefits for retirees and their spouses (and Medicare Part B reimbursement for certain retirees), and retiree life insurance. Savings Plans SoCalGas offers a savings plan, administered by plan trustees, to all eligible employees. Eligibility to participate in the plan is immediate for salary deferrals. Employees may contribute, subject to plan provisions, from one percent to 15 percent of their regular earnings. The employee's contributions, at the direction of the employees, are primarily invested in Sempra Energy stock, mutual funds or guaranteed investment contracts. Employer contributions, after one year of completed service, are made in shares of Sempra Energy common stock. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. Employer contributions for the SoCalGas plan are partially funded by the Sempra Energy Employee Stock Ownership Plan and Trust (formerly Pacific Enterprises Employee Stock Ownership Plan and Trust). Annual expense for the savings plans was $6 million in 1999, $7 million in 1998 and $7 million in 1997. NOTE 7: STOCK-BASED COMPENSATION Sempra Energy has stock-based compensation plans that align employee and shareholder objectives related to Sempra Energy's long-term growth. The long-term incentive stock compensation plan provides for aggregate awards of Sempra Energy non-qualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments or dividend equivalents. In 1995, Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based compensation," was issued. It encourages a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS No. 123, Sempra Energy and its subsidiaries adopted its disclosure-only requirements and continue to account for stock-based compensation in accordance with the provisions of accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." To the extent that subsidiary employees participate in the plans or that subsidiaries are allocated a portion of Sempra Energy's costs of the plans, the subsidiaries record an expense for the plans. SoCalGas recorded expenses of $4 million in each of 1998 and 1997. In 1999 SoCalGas' share of the plans' income was $4 million. NOTE 8: FINANCIAL INSTRUMENTS Fair Value The fair values of the Company's financial instruments are not materially different from the carrying amounts, except for long- term debt and preferred stock. The carrying amounts and fair values of long-term debt are $1.0 billion and $0.9 billion, respectively, at December 31, 1999, and $1.1 billion each at December 31, 1998. The carrying amounts and fair values of preferred stock are $22 million and $17 million, respectively, at December 31, 1999, and $22 million and $8 million, respectively, at December 31, 1998. The fair values of the first-mortgage and other bonds and preferred stock are estimated based on quoted market prices. The fair values of long-term notes payable are based on the present value of the future cash flows, discounted at rates available for similar notes with comparable maturities. Off-Balance-Sheet Financial Instruments The Company's policy is to use derivative financial instruments to manage its exposure to fluctuations in interest rates, foreign- currency exchange rates and energy prices. Transactions involving these financial instruments expose the Company to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. Energy Derivatives The Company's regulated operations use energy derivatives for price risk management purposes within certain limitations imposed by Company policies and regulatory requirements. SoCalGas is subject to price risk on its natural gas purchases if its cost exceeds a 2 percent tolerance band above the benchmark price. This is discussed further in Note 11. SoCalGas becomes subject to price risk when positions are incurred during the buying, selling and storing of natural gas. As a result of the Gas Cost Incentive Mechanism (GCIM), the Company enters into a certain amount of natural gas futures contracts in the open market with the intent of reducing natural gas costs within the GCIM tolerance band. The Company's policy is to use natural gas futures contracts to mitigate risk and better manage natural gas costs. The CPUC has approved the use of natural gas futures for managing risk associated with the GCIM. For the years ended December 31, 1999, 1998 and 1997, gains and losses from natural gas futures contracts are not material to SoCalGas' financial statements. NOTE 9: SHAREHOLDERS' EQUITY - ----------------------------------------------------------------- December 31, (Dollars in millions) 1999 1998 - ----------------------------------------------------------------- COMMON EQUITY: Common stock, without par value, authorized 100,000,000 shares, 91,300,000 shares outstanding $ 835 $ 835 Retained earnings 447 525 Accumulated other comprehensive income 6 -- -------------------------- Total common equity $ 1,288 $ 1,360 - ----------------------------------------------------------------- All shares of SoCalGas common stock are wholly owned by Pacific Enterprises. - ----------------------------------------------------------------- December 31, (Dollars in millions) 1999 1998 - ----------------------------------------------------------------- PREFERRED STOCK: Not subject to mandatory redemption: $25 par value, authorized 1,000,000 shares 6% Series, 79,011 shares outstanding $ 3 $ 3 6% Series A, 783,032 shares outstanding 19 19 --------------- $22 $22 - ----------------------------------------------------------------- None of SoCalGas' series of preferred stock are callable. All series have one vote per share and cumulative preferences as to dividends. On February 2, 1998, SoCalGas redeemed all outstanding shares of 7.75% Series Preferred Stock at a price per share of $25 plus $0.09 of dividends accruing to the date of redemption. The total cost to SoCalGas was approximately $75.3 million. Dividend Restrictions The CPUC regulates SoCalGas' capital structure, limiting the dividends it may pay. At December 31, 1999, $267 million of SoCalGas' retained earnings was available for future dividends. NOTE 10: CONTINGENCIES AND COMMITMENTS Natural Gas Contracts SoCalGas buys natural gas under several short-term and long-term contracts. Short-term purchases are primarily from various U.S. Southwest and Canadian gas suppliers, and are based on monthly spot-market prices. In 1998, SoCalGas restructured its long-term commodity purchase contracts with suppliers of California offshore and Canadian gas. These new purchase contracts expire at the end of 2003. SoCalGas has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through the year 2006. These agreements provide for payments of an annual reservation charge. SoCalGas recovers such fixed charges in rates. At December 31, 1999, the future minimum payments under natural gas contracts were: - ----------------------------------------------------------------- Storage and (Dollars in millions) Transportation Natural Gas - ----------------------------------------------------------------- 2000 $ 182 $ 399 2001 184 165 2002 186 170 2003 186 158 2004 183 - Thereafter 315 - ---------------------------------- Total minimum payments $1,236 $ 892 - ----------------------------------------------------------------- Total payments under the contracts were $1.1 billion in 1999, $0.9 billion in 1998, and $1.1 billion in 1997. Leases SoCalGas has operating leases on real and personal property expiring at various dates from 2000 to 2029. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain options to extend, which are exercisable by SoCalGas. The minimum rental commitments payable in future years under all noncancellable leases are: - ----------------------------------------------------------------- Operating (Dollars in millions) Leases - ----------------------------------------------------------------- 2000 $ 28 2001 27 2002 29 2003 27 2004 28 Thereafter 219 - ----------------------------------------------------------------- Total future rental commitment $ 358 - ----------------------------------------------------------------- Rent expense totaled $39 million in 1999, $43 million in 1998 and $44 million in 1997. Other Commitments and Contingencies December 31, 1999, commitments for capital expenditures were approximately $8 million. Environmental Issues The Company's operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. SoCalGas incurs significant costs to operate its facilities in compliance with these laws and regulations and these costs generally have been recovered in customer rates. In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account allowing utilities to recover their hazardous waste costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses is permitted. In addition, the Company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. Environmental liabilities that may arise are recorded when remedial efforts are probable and the costs can be estimated. SoCalGas' capital expenditures to comply with environmental laws and regulations were $1 million in each of 1999, 1998 and 1997, and are not expected to be significant over the next five years. SoCalGas has been associated with various sites which may require remediation under federal, state or local environmental laws. SoCalGas is unable to determine fully the extent of its responsibility for remediation of these sites until assessments are completed. Furthermore, the number of others that also may be responsible, and their ability to share in the cost of the cleanup, is not known. Litigation The Company is involved in various legal matters, including those arising out of the ordinary course of business. Management believes that these matters will not have a material adverse effect on the Company's results of operations, financial condition or liquidity. Concentration of Credit Risk The Company maintains credit policies and systems to minimize overall credit risk. These policies include, when applicable, the use of an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. SoCalGas grants credit to its utility customers, substantially all of whom are located in its service territory, which covers most of Southern California and a portion of central California. NOTE 11: REGULATORY MATTERS Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating gas sales to noncore customers. On January 21, 1998, the CPUC issued a staff report initiating a proceeding to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California's natural gas consumers. In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas industry restructuring decision for core (residential and small commercial) customers prior to January 1, 2000. During the implementation moratorium, the CPUC held hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. SoCalGas has been actively participating in this effort and has argued in support of competition intended to maximize benefits to customers rather than to protect competitors. In October 1999, the State of California enacted a law (AB 1421) which requires that gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue-cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a non-utility provider. The law prohibits the CPUC from further unbundling of distribution-related gas services (including meter reading and billing) and after-meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for most customers. The objective is to preserve both customer safety and customer choice. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for SoCalGas. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity measures, as well as cost reductions, rather than relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure. SoCalGas' PBR mechanism is in effect through December 31, 2002; however, the CPUC decision allows for the possibility that changes to its mechanism could be adopted in its 1999 Biennial Cost Allocation Proceeding decision, which is anticipated during the second quarter of 2000. SoCalGas' PBR mechanism is scheduled to be updated at December 31, 2002, at which time it will be updated for, among other things, changes in costs and volumes. Key elements of the mechanism include an initial reduction in base rates, an indexing mechanism that limits future rate increases to the inflation rate less a productivity factor, a sharing mechanism with customers if earnings exceed the authorized rate of return on rate base, and rate refunds to customers if service quality deteriorates. Specifically, the key elements of the mechanism include the following: - -- Earnings up to 25 basis points in excess of the authorized rate of return on rate base are retained 100 percent by shareholders. Earnings that exceed the authorized rate of return on rate base by greater than 25 basis points are shared between customers and shareholders on a sliding scale that begins with 75 percent of the additional earnings being given back to customers and declining to 0 percent as earned returns approach 300 basis points above authorized amounts. There is no sharing if actual earnings fall below the authorized rate of return. In 1999, SoCalGas was authorized to earn a 9.49 percent return on its rate base. The same rate of return is authorized for 2000. - -- Base rates are indexed based on inflation less an estimated productivity factor. - -- Performance indicators, including employee safety, customer satisfaction, and call-center responsiveness, affect the Company's future income potential. The SoCalGas mechanism authorizes penalties up to $4 million annually, or more in certain, limited situations. - -- The SoCalGas mechanism allows for pricing flexibility for residential and small commercial customers, with any shortfalls in revenue being borne by shareholders and with any increase in revenue shared between shareholders and customers. - -- Annual cost of capital proceedings are replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. The SoCalGas mechanism is triggered if the 12-month trailing average of actual market interest rates increases or decreases by more than 150 basis points and is forecasted to continue to vary by at least 150 basis points for the next year. If this occurs, there would be an automatic adjustment of rates for the change in the cost of capital according to a formula which applies a percentage of the change to various capital components. Comprehensive Settlement Of Natural Gas Regulatory Issues In July 1994, the CPUC approved a comprehensive settlement for SoCalGas (Comprehensive Settlement) of a number of regulatory issues, including rate recovery of a significant portion of the restructuring costs associated with certain long-term contracts with suppliers of California-offshore and Canadian natural gas. In the past, the cost of these supplies had been substantially in excess of SoCalGas' average delivered cost for all natural gas supplies. The restructured contracts substantially reduced the ongoing delivered costs of these supplies. The Comprehensive Settlement permitted SoCalGas to recover in utility rates approximately 80 percent of the contract-restructuring costs of $391 million and accelerated amortization of related pipeline assets of approximately $140 million, together with interest, incurred prior to January 1, 1999. In addition to the supply issues, the Comprehensive Settlement addressed the following other regulatory issues: - -- Noncore revenues were governed by the Comprehensive Settlement through July 31, 1999. This treatment is being replaced by the PBR mechanism as adopted in the 1999 Biennial Cost Allocation Proceeding (BCAP). The CPUC's proposed decision on the 1999 BCAP would allow balancing account treatment for 75 percent of noncore revenues. - --The Gas Cost Incentive Mechanism (GCIM) for evaluating SoCalGas' natural gas purchases substantially replaced the previous process of reasonableness reviews. In December 1998 the CPUC extended the GCIM program indefinitely. GCIM compares SoCalGas' cost of natural gas with a benchmark level, which is the average price of 30-day firm spot supplies in the basins in which SoCalGas purchases natural gas. The mechanism permits full recovery of all costs within a "tolerance band" above the benchmark price and refunds all savings within a "tolerance band" below the benchmark price. The costs or savings outside the "tolerance band" are shared equally between customers and shareholders. The CPUC approved the use of natural gas futures for managing risk associated with the GCIM. SoCalGas enters into natural gas futures contracts in the open market on a limited basis to mitigate risk and better manage natural gas costs. In 1998 the CPUC approved GCIM-related shareholder awards to SoCalGas totaling $13 million. In June 1999, SoCalGas filed its annual GCIM application with the CPUC requesting an award of $8 million for the annual period ended March 31, 1999. A CPUC decision is expected during the second quarter of 2000. Biennial Cost Allocation Proceeding (BCAP) In the second quarter of 1997, the CPUC issued a decision on SoCalGas' 1996 BCAP filing. In this decision, the CPUC considered SoCalGas' relinquishments of interstate pipeline capacity on the El Paso and Transwestern pipelines. This resulted in a reduction in the pipeline demand charges allocated to SoCalGas' customers and surcharges allocated to firm capacity holders through pipeline rate-case settlements adopted at the FERC. However FERC is reviewing the decision. On November 4, 1999, the CPUC issued a decision on the 1996 BCAP, shifting $88 million of pipeline surcharges from the pipeline capacity relinquishments to noncore customers. The noncore customer rate impact of the decision is mitigated by overcollections in the regulatory accounts and will be reflected in the rates adopted in the final 1999 BCAP decision. In October 1998, SoCalGas filed its 1999 BCAP application requesting that new rates become effective August 1, 1999 and remain in effect through December 31, 2002. The proposed beginning date follows the conclusion of SoCalGas' Comprehensive Settlement (discussed above), and the proposed end date aligns with the expiration of its current PBR. On January 11, 2000, the CPUC issued a proposed decision adopting an overall decrease in natural gas revenues of $208 million for SoCalGas. A final CPUC decision is expected in the second quarter of 2000. Cost Of Capital For 2000, SoCalGas is authorized to earn a rate of return on common equity of 11.6 percent and a 9.49 percent return on rate base, the same as in 1999, unless interest-rate changes are large enough to trigger an automatic adjustment as discussed above under "Performance-Based Regulation." Transactions Between Utilities and Affiliated Companies On December 16, 1997, the CPUC adopted rules, effective January 1, 1998, establishing uniform standards of conduct governing the manner in which California's investor-owned utilities (IOUs) conduct business with their energy-related affiliates. The objective of the affiliate-transaction rules is to ensure that these affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. The rules establish standards relating to non-discrimination, disclosure and information exchange, and separation of activities. The CPUC excluded utility- to-utility transactions between SDG&E and SoCalGas from the affiliate-transaction rules in its March 1998 decision approving the business combination of Enova and PE, which is described in Note 1. Other affiliates sold and transported natural gas to the Company under tariffs approved by the FERC. Billings for the purchases totaled $0 in 1999 and $252 million in each of the years 1998 and 1997. The decrease in 1999 is due to the sale of the related facilities and contracts in late 1998. During 1999, 1998 and 1997, the Company sold natural gas transportation and storage services to SDG&E in the amount of $50 million to $60 million per year. These sales were at rates established by the CPUC. NOTE 12: SEGMENT INFORMATION The Company has two separately managed reportable segments: natural gas distribution, and natural gas transmission/storage. The accounting policies of the segments are the same as those described in Note 2, and segment performance is evaluated by management based on reported operating income. Intersegment transactions generally are recorded the same as sales or transactions with third parties. Interest expense and income tax expense are not allocated to the reportable segments. Interest revenue is included in other income on the Statements of Consolidated Income. It is not allocated to the reportable segments and, therefore, is not presented in the tables below. - -------------------------------------------------------------------- For the year ended December 31, (Dollars in millions) 1999 1998 1997 - -------------------------------------------------------------------- Revenues: Distribution $ 2,259 $ 2,159 $ 2,283 Transmission & storage 297 266 337 All other 13 2 21 ------------------------------------ Total $ 2,569 $ 2,427 $ 2,641 ------------------------------------ Depreciation and amortization: Distribution $ 205 $ 200 $ 197 Transmission & storage 55 54 54 ------------------------------------ Total $ 260 $ 254 $ 251 ------------------------------------ Segment Income: Distribution $ 355 $ 300 $ 383 Transmission & storage 76 64 87 All other 16 -- 22 ------------------------------------ Total segment income 447 364 492 ------------------------------------ Interest expense (60) (80) (87) Income tax expense (182) (128) (178) Nonoperating income (4) 3 11 ------------------------------------ Net income $ 201 $ 159 $ 238 ------------------------------------ - -------------------------------------------------------------------- At December 31, or for the year then ended 1999 1998 1997 - -------------------------------------------------------------------- Assets: Distribution $ 1,163 $ 2,373 $ 2,946 Transmission & storage 1,746 1,184 1,207 All other 623 277 52 ------------------------------------ Total $ 3,532 $ 3,834 $ 4,205 ------------------------------------ Capital Expenditures: Distribution $ 100 $ 92 $ 110 Transmission & storage 17 15 24 All other 29 21 25 ------------------------------------ Total $ 146 $ 128 $ 159 ------------------------------------ Geographic Information: Long-lived assets United States $ 2,868 $ 2,955 $ 3,077 - -------------------------------------------------------------------- NOTE 13: QUARTERLY FINANCIAL DATA (UNAUDITED) Quarter ended ------------------------------------------------------- Dollars in millions March 31 June 30 September 30 December 31 - --------------------------------------------------------------------------------------- 1999 Operating revenues $ 607 $ 624 $ 562 $ 776 Operating expenses 537 560 494 710 ----------------------------------------------------- Operating income $ 70 $ 64 $ 68 $ 66 ----------------------------------------------------- Net income $ 47 $ 47 $ 48 $ 59 Dividends on preferred stock - 1 - - ----------------------------------------------------- Net income applicable to common shares $ 47 $ 46 $ 48 $ 59 ===================================================== 1998 Operating revenues $ 664 $ 578 $ 520 $ 665 Operating expenses 594 537 449 609 ----------------------------------------------------- Operating income $ 70 $ 41 $ 71 $ 56 ----------------------------------------------------- Net income $ 48 $ 19 $ 54 $ 38 Dividends on preferred stock 1 - - - ----------------------------------------------------- Net income applicable to common shares $ 47 $ 19 $ 54 $ 38 ===================================================== Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required on Identification of Directors is incorporated by reference from "Election of Directors" in the Information Statement prepared for the May 2000 annual meeting of shareholders. The information required on the Company's executive officers is set forth below. EXECUTIVE OFFICERS OF THE REGISTRANT Name Age* Positions - ------------------------------------------------------------------- Warren I. Mitchell 62 Chairman and President Lee M. Stewart 54 Senior Vice President and Corporate Secretary; President-Energy Transportation Services Debra L. Reed 43 Senior Vice President and Chief Financial Officer; President-Energy Distribution Services Richard M. Morrow 50 Vice President Roy M. Rawlings 55 Vice President Anne S. Smith 46 Vice President George E. Strang 60 Vice President * As of December 31, 1999 Each Executive Officer has been an officer of SoCalGas for more than five years. ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 is incorporated by reference from "Election of Directors" and "Executive Compensation" in the Information Statement prepared for the May 2000 annual meeting of shareholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 is incorporated by reference from "Election of Directors" in the Information Statement prepared for the May 2000 annual meeting of shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: 1. Financial statements Page in This Report Independent Auditors' Report . . . . . . . . . . . . . . 26 Statements of Consolidated Income for the years ended December 31, 1999, 1998 and 1997 . . . . . . . . 27 Consolidated Balance Sheets at December 31, 1999 and 1998. . . . . . . . . . . . . . . . . . . . . 28 Statements of Consolidated Cash Flows for the years ended December 31, 1999, 1998 and 1997 . . . . . 30 Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 1999, 1998 and 1997 . . . . . . . . . . . 31 Notes to Consolidated Financial Statements . . . . . . . 32 2. Financial statement schedules None. Schedules for which provision is made in Regulation S-X are not required under the instructions contained therein or are inapplicable. 3. Exhibits See Exhibit Index on page 56 of this report. (b) Reports on Form 8-K There were no reports on Form 8-K filed after September 30, 1999. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized. SOUTHERN CALIFORNIA GAS COMPANY By: /s/ Warren I. Mitchell . Warren I. Mitchell Chairman and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated. Name/Title Signature Date Principal Executive Officers: Warren I. Mitchell Chairman, President /s/ Warren I. Mitchell March 7, 2000 Principal Financial Officer: Debra L. Reed Senior Vice President, Chief Financial Officer /s/ Debra L. Reed March 7, 2000 Principal Accounting Officer: Debra L. Reed Senior Vice President, Chief Financial Officer /s/ Debra L. Reed March 7, 2000 Directors: Warren I. Mitchell Chairman /s/ Warren I. Mitchell March 7, 2000 Hyla H. Bertea, Director /s/ Hyla H. Bertea March 7, 2000 Ann L. Burr, Director /s/ Ann L. Burr March 7, 2000 Herbert L. Carter, Director /s/ Herbert L. Carter March 7, 2000 Richard A. Collato, Director /s/ Richard A. Collato March 7, 2000 Daniel W. Derbes, Director /s/ Daniel W. Derbes March 7, 2000 Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 7, 2000 Robert H. Goldsmith, Director /s/ Robert H. Goldsmith March 7, 2000 William D. Jones, Director /s/ William D. Jones March 7, 2000 Ignacio E. Lozano, Jr., Director /s/ Ignacio E. Lozano, Jr. March 7, 2000 Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 7, 2000 William G. Ouchi, Director /s/ William G. Ouchi March 7, 2000 Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 7, 2000 Thomas C. Stickel, Director /s/ Thomas C. Stickel March 7, 2000 Diana L. Walker, Director /s/ Diana L. Walker March 7, 2000 EXHIBIT INDEX The Forms 8-K, 10-K and 10-Q referred to herein were filed under Commission File Number 1-14201 (Sempra Energy), Commission File Number 1-40 (Pacific Enterprises) and/or Commission File Number 1-1402 (Southern California Gas Company). Exhibit 3 -- By-Laws and Articles Of Incorporation 3.01 Restated Articles of Incorporation of Southern California Gas Company (Southern California Gas Company 1996 Form 10-K; Exhibit 3.01). 3.02 Bylaws of Southern California Gas Company dated September 1, 1998 (Southern California Gas Company 1998 Form 10-K; Exhibit 3.02). Exhibit 4 -- Instruments Defining The Rights Of Security Holders The Company agrees to furnish a copy of each such instrument to the Commission upon request. 4.01 Specimen Preferred Stock Certificates of Southern California Gas Company (Southern California Gas Company 1980 Form 10-K; Exhibit 4.01). 4.02 First Mortgage Indenture of Southern California Gas Company to American Trust Company dated as of October 1, 1940 (Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940; Exhibit B-4). 4.03 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of July 1, 1947 (Registration Statement No. 2-7072 filed by Southern California Gas Company on March 15, 1947; Exhibit B-5). 4.04 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955 (Registration Statement No. 2-11997 filed by Pacific Lighting Corporation on October 26, 1955; Exhibit 4.07). 4.05 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of June 1, 1956 (Registration Statement No. 2-12456 filed by Southern California Gas Company on April 23, 1956; Exhibit 2.08). 4.06 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972 (Registration Statement No. 2-59832 filed by Southern California Gas Company on September 6, 1977; Exhibit 2.19). 4.07 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976 (Registration Statement No. 2-56034 filed by Southern California Gas Company on April 14, 1976; Exhibit 2.20). 4.08 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981 (Pacific Lighting Corporation 1981 Form 10-K; Exhibit 4.25). 4.09 Supplemental Indenture of Southern California Gas Company to Manufacturers Hanover Trust Company of California, successor to Wells Fargo Bank, National Association, and Crocker National Bank as Successor Trustee dated as of May 18, 1984 (Southern California Gas Company 1984 Form 10-K; Exhibit 4.29). 4.10 Supplemental Indenture of Southern California Gas Company to Bankers Trust Company of California, N.A., successor to Wells Fargo Bank, National Association dated as of January 15, 1988 (Pacific Lighting Corporation 1987 Form 10-K; Exhibit 4.11). 4.11 Supplemental Indenture of Southern California Gas Company to First Trust of California, National Association, successor to Bankers Trust Company of California, N.A. dated as of August 15, 1992 (Registration Statement No. 33-50826 filed by Southern California Gas Company on August 13, 1992; Exhibit 4.37). 4.12 Specimen 7 3/4% Series Preferred Stock Certificate (Southern California Gas Company 1992 Form 10-K; Exhibit 4.15). Exhibit 10 -- Material Contracts Compensation 10.01 Sempra Energy Supplemental Executive Retirement Plan as amended and restated effective July 1, 1998. (1998 Sempra Energy Form 10-K Exhibit 10.09). 10.02 Sempra Energy Executive Incentive Plan effective June 1, 1998. (1998 Sempra Energy Form 10-K Exhibit 10.11). 10.03 Sempra Energy Executive Deferred Compensation Agreement effective June 1, 1998. (1998 Sempra Energy Form 10-K Exhibit 10.12). 10.04 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998 (Exhibit 4.1)). 10.05 Amended and Restated Pacific Enterprises Employee Stock Option Plan (Southern California Gas Company 1996 Form 10-K; Exhibit 10.10). Exhibit 21 -- Subsidiaries 21.01 Schedule of Subsidiaries at December 31, 1999. Exhibit 23 -- Consents Of Experts And Counsel 23.01 Independent Auditors' Consent Exhibit 27 -- Financial Data Schedule 27.01 Financial Data Schedule for the year ended December 31, 1999. GLOSSARY AFUDC Allowance for Funds Used During Construction BCAP Biennial Cost Allocation Proceeding Bcf Billion Cubic Feet (of natural gas) CPUC California Public Utilities Commission Enova Enova Corporation FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GCIM Gas Cost Incentive Mechanism IDBs Industrial Development Bonds IOUs Investor-Owned Utilities ORA Office of Ratepayer Advocates PBR Performance-Based Ratemaking/Regulation PE Pacific Enterprises, the Company's parent PRP Potential Responsible Party SDG&E San Diego Gas & Electric Company SFAS Statement of Financial Accounting Standards SoCalGas Southern California Gas Company UEG Utility Electric Generation VaR Value at Risk